IR 05000313/1993009
| ML20058P952 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 12/17/1993 |
| From: | Stetka T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20058P944 | List: |
| References | |
| 50-313-93-09, 50-313-93-9, 50-368-93-09, 50-368-93-9, NUDOCS 9312280023 | |
| Download: ML20058P952 (18) | |
Text
. . .
,
- -
_
.
'
APPENDIX B U.S. NUCLEAR REGULATORY COMMISSION 1
!
REGION IV
Inspection Report: 50-313/93-09 ;
50-368/93-09 Operating Licenses: DPR-51 1 NPF-6 .
.
Licensee: Entergy Operations, In Route 3, Box 137G Russellville, Arkansas ;
Facility Name: Arkansas Nuclear One, Units 1 and 2 Inspection At: Russellville, Arkansas .j Inspection Conducted: October 3 through November 13, 1993 :
'
Inspectors: L. Smith, Senior Resident Inspector _
S. Campbell, Resident Inspector R. Vickrey, Reactor Inspector Accompanying Personnel: K. Weaver, Engineering Aide :
.
L ,
Approvad: / 9 M //2JD /2f/7f93-Dath '
Thomas F. Stetka, Chief, Project Section D Inspection Summary I
Areas Inspected (Units 1 and 2): This routine, unannounced inspection addressed onsite event followup, operational safety verification, monthly maintenance observation, bimonthly observation of surveillance, followup on previous inspection items, and onsite review of licensee event reports (LERs).
Results (Units 1 and 2):
- Unit 1 integrated engineered safeguards actuation system (ESAS) test equipment instructions were not sufficiently detailed in relation to the complexity of the task. This was determined to be a noncited violation -
(Section 2.1.2)
- The licensee failed to complete the corrective action required by a l Unit I condition report in that a speed switch was not replaced on an
)
l i
9312280023 931217 'l PDR ADOCK 05000313 -j G PDR - c
'
y
'
. .
.
-2- ,
i emergency diesel generator (EDG) at the end of its recommended lif This was determined to be a violation (Section 2.1.3).
- More than 500 tasks with a worktype of preventive maintenance (PM), !
mandatory preventive maintenance (MPM), or environmental qualification (EVQ) tasks were not implemented (Section 2.1.3).
- The licensee failed to identify and replace all the insulation which was -
contaminated by the turbine lube oil spill prior to restart resulting in two small fires (Section 2.2).
- The licensee's evaluation and assessment of the Unit 1 emergency ,
feedwater pipe vibration was prompt and thorough (Section 3.2).
- An unresolved item was identified to evaluate the design change controls in place for reactor coolant pump (RCP) seal modifications (Section 3.5).
. Failure to adequately perform a Unit I reactor building preheatup inspection as described by the licensee's procedure was determined to be a violation (Section 3.6).
- Failure to identify that fire water leaked onto an inadequate core cooling monitor display system (ICCMDS) junction box whenever the fire system surveillance performed was considered to be a weakness *
(Section 3.7).
- Failure to have two Unit 2 postaccident sampling system (PASS) valves in ,
a position required by procedure was considered to be a violation '
(Section 3.8).
. All observed maintenance and test activities were appropriately performed. However, the Unit I diesel fire pump inspection was not documented as steps were performe This was viewed as a weakness !
(Section 4 and 5).
- The engineering evaluation of the operability of the low pressure injection pump for Unit I was a strength (Section 6.2).
!
Summary of Inspection Findings:
'
,
- Two noncited violations were identified (Sections 2.1.2.and 3.6). f
- Violation 313/9309-01 was opened (Section 2.1.3).
- Violation 368/9309-02 was opened-(Section 3.8).
. Unresolved Item 313/9309-03 was opened (Section 3.5). l
!
i
___
.
. .
~~
-3-
- Inspection Followup Iteia (IFI) 313/9309-04; 368/9309-04 was opened (Section 3.12).
- IFI 368/9309-05 was opened (Section 4.1). ,
- LER 368/92-009 was closed (Section 6.1).
- LER 313/93-003 was closed (Section 6.2).
- IFI 313/9305-01 was closed (Section 7.1).
Attachments: .
- Attachment - Persons Contacted and Exit Meeting
,
i t
.s
.
,
j i
l l
.
. .
.
-4-del > 'S 1 PLANT STATUS Unit 1 At the beginning of the inspection period, Unit I was in Refueling Outage IRll. On October 18 the reactor was made critical and the unit began a power increase to 30 percen Power was reduced to 3 percent on October 19 due to an insulation fire on the high pressure turbine extraction steam piping. On October 20 the unit commenced a power increase and reached 70 percent. On October 21 power was reduced to 26 percent due to a second insulation fire. The unit commenced a power increase and reached 100 percent power on October 24. On October 28 the unit commenced a power reduction at 30 percent per hour to cold shutdown for RCP seal replacements. On November 3 the unit commenced a power increase and reached 100 percent power on November 4. On Novcmber 6 the unit reduced power to 45 percent for a main feedwater pump lube oil leak. The unit returned to 100 percent power on November'7 and remained at that power level through the end of the inspection-perio .2 Unit 2 The unit remained at or near 100 percent power throughout the inspectio ONSITE EVENT FOLLOWUP (93702)
2.1 Unit 1 - Failure of EDG Output Feeder Breaker A-308 to Close 2. Event Description On October 4,1993, with the unit in a refueling outage, the normal feeder breaker from 4160V Bus A-1 to the 4160V Safety Bus A-3,_ Tie Breaker A-309, opened with no apparent cause. Safety Bus A-3 deenergized and EDG K-4A auto-started as designed, but Diesel Output Breaker A-308 failed to close to supply power to Bus A- As a result of the deenergized safety bus, service water was not available for cooling the EDG. Following two unsuccessful attempts by control room operators to close Diesel Output Breaker A-308, EDG K-4A was secured. Troubleshooting revealed a faulty latch checking switch in Breaker A-308. The breaker was repaired and a satisfactory bench test was performe At the time of this event, the licensee was making preparations for an integrated ESAS test. The licensee believed that while installing a computer monitor point for Breaker A-309, a worker inadvertently created a short circuit which caused Breaker A-309 to tri On October 5, following replacement of the latch check switch on Diesel Output Breaker A-308, operators attempted to start EDK-4A from the control room to m.. _
r a
!
.
. .
i
~
-5-
{
!
verify proper output breaker operation. The EDG did not start upon depressing :
the start button located on Panel C-10. The EDG did start on the second attempt, however, approximately 30 seconds were required for it to obtain rated voltage. The EDG is required by surveillance test to achieve cated !
'
voltage in less than 15 seconds. An operator located in the diesel generator room observed that service water supply Valve CV-3806 opened prior to air .
start motor actuation, which is an atypical sequence. The licensee theorized i that the cause of-this event was an intermittent failure of either a control relay or the speed sensing relay (speed switch), but they were unable to ,
pinpoint the caust of failure. The licensee replaced the suspect speed switch ;
'
and control relays. Preliminary checks of the replaced components detected no unusual fi: tog ,
.
The licensie initiated Condition Report 1-93-408 and determined the condition to be signi'ican LER 313/93-004 was submitted per 10 CFR 50.73 (a)(2)(iv).
2.1.2 Coincident Integrated ESAS Testing In response to these events, the inspector initiated a review of Job ;
Order (J0) 00891118 and Procedure 1305.006, Revision 14, " Integrated ES System l Test." The procedure required instrumentation and controls technicians to !
'
connect the test equipment per Attachment 7, " Test Instrument Connections."
Note 1 of Attachment 7 stated that "If the Esterline Angus Recorder is used, all monitored indications are 125 VDL and require a 3K ohm, 3 watt recorder input resistor." After the connections had been completed for Breaker A-309, the instrumentation and controls technician had a discussion with the data acquisition system engineer about where the dropping resistor should be in the .
circui Based on this discussion, the technician disconnected hard wired l leads at the test equipment terminal board and relanded them in reverse orde ;
Concurrent with this activity, Breaker A-309 trippe ;
Procedure 1305.006 addressed the test lead connections inside Panel C-10 but !
did not address the configuration of the test equipment. The inspector l concurred with the licensee that the integrated ESAS test equipment i instructions were not sufficiently detailed in relation to the complexity of :
the task. This was a violation of 10 CFR 50, Appendix B, Criterion V, which 4
'
states that activities affecting quality shall be prescribed by. documented instructions and procedures of a type appropriate to the circumstance :
This violation is not being cited because the criteria in Paragraph VII.B.2 of _
Appendix C to 10 CFR Part 2 of the NRC's " Rules of Practice," were satisfie !
i Procedure 1305.006, " Integrated ES System Test," was revised to' address shorting of leads during test setup. The licensee made the following additional commitments: ;
Prior to the next scheduled ESAS test, a new procedure fcr
'
conducting ESAS testing will be developed to provide specific 1 instructions for the setup of ESAS test equipment and to ensure j s
l
.
r 7
.
-!
'
-6-
,
&
polarity requirements are described. This procedure development will be completed by June 1, 199 * Arkansas Nuclear One Systems Engineering wi.1 evaluate the testing of the ESAS control circuits to determine if enhancements can b made to minimize work in cramped spaces during interface connections. This evaluation will be completed by June 1,199 ,
- The lessons learned regarding the performance of self-checking to prevent coupleting engineered safeguard bus connections while performing testing will be discussed with the appropriate Unit 1 maintenance personnel by December 31, 199 * Unit 2 maintenance will review their performance of ESAS testing and implement changes or lessons' learned training as necessary by :
March 31, 199 .1.3 Review of Prior Condition Reports
,
In response to this event, the inspectors reviewed Condition Report 1-93-0362, dated September 27, 1993, which identified problems related_ to the-failure of EDG K-4A to start from the control room during the performance of an endurance run and load rejection test conducted in accordance with Procedure 1104.036, Supplement 9, " Emergency Diesel Generator Operation." Attached to.the condition report was a listing of condition reports related to '
Procedure 1104.036. Condition Report 1-89-0501, related to a failure of the EDG to. start from the control room during the performance of an endurance run and load rejection test, identified the cause as a failed speed sensing relay .
(speed switch). One of the corrective actions listed in this condition report was to detarmine the qualified life for the speed switches and implement
'
controls to ensure that the speed switches were periodically replace The speed switch vendor determined that the. normal life expectancy of the switch was 5 years. The licensee revised PM Engineering. Evaluation 106,
"EDG-Generator, Exciter and Voltage Regulator," Revision 3, to establish periodic replacement of these switches at 4.5 year intervals. Additionally, Procedure 1412.201, " Unit 1 Emergency Diesel Generator Speed Sensing Switch ;
Replacement," Revision 0, was approved April 27, 1990,_but not implemente As a result the speed switches were not replaced within the prescribed time interva In'1991 the licensee re-evaluated this condition report to either revise the ;
corrective action plan as necessary or document why no further action was _
required. The licensee's re-evaluation of the condition report did not revise the corrective action plan and' documented that no iurther action (additional ,
to that already required by the condition report) was require .
The failure to complete the corrective action identified in Condition Report 1-89-501 and replace the speed switches within the apparent qualified life was :
l
~
. .
- '
_7_
considered to be contrary to the requirements of 10 CFR 50, Appendix B Criterion XVI, " Corrective Action." This issue was identified as a violation i (313/9309-01). .
The licensee contacted the speed switch vendor, other utilities, and the EDG vendor to identify industry failure data related to the speed switches. The speed switch vendor indicated that the only outstanding issues with the speed
. switches involved severe unit operating conditions and that they no longer supported their previous position that the normal life expectancy of the speed :
switch was 5 years. The EDG vendor and two other utilities indicated that there were no issues or noted failures in this area to date. The licensee stated they would continue to seek additional information in this area but felt that their prior position of a 5-year qualified life for the speed .
e switches was unwarranted and, therefore, not a valid concern for the presently- t installed switches. The inspectors questioned whether the Unit 2 diesels had .
the same speed switches and the licensee stated that they di The inspectors found that Procedure 1412.201 was among more than 500 tasks with a worktype of PM, MPM, or EQV which the licensee had not implemente The inspectors asked the licensee if any of the unissued tasks might similarly-identify other limited life components on safety-related equipment that were past due for replacement. The licensee stated that a review of PM, MPM, and EVQ tasks for safety-related components was performed to identify those tasks that have not been approved and have no past accomplished dates; and those -
tasks which have been approved, but have no assigned due dates. No additional
'
concerns 'were identified. The licensee also made the following commitments:
. Procedure 1000.115, " Preventive Maintenance Program," and other :
supporting procedures will be revised to define responsibilities !
and methods for tracking all unapproved PM/MPM/EVQ tasks on Unit 1 !
and Unit 2. This action is expected to be completed by '
December 20, 199 . Evaluate revising the definition of " Mandatory Preventive $
Maintenance," in all applicable procedurer to include tasks that ,
must be performed to replace non-EQ limited life Q/F/S parts or ;,
component l 2.2 Unit 1 - High Pressure Turbine Fire j During Refueling Outage IRll, a turbine lube oil bearing flush was conducte During this flush, the turbine bearings were bypassed by temporary 3-inch l Schedule 40.PVC piping. A coupling in this PVC.line cracked and allowed approximately 150 gallons of turbine lube oil to leak onto the high pressure :
turbine extraction steam line insulatio ,
!
The licensee cleaned up the oil and replaced the insulation which had known 4 oil contamination. The licensee sampled nearby insulation and replaced i additional insulation which was also determined to be oil soaked. A fire .
f
'
m .
..
. .
~
-8- !
!
,
'
watch was placed at the turbine during power escalation following Refueling Outage IRll. On October 19 smoke was identified by the licensee in the area of the high pressure turbine extraction steam lines. The licensee determined '
that all of the lube oil soaked insulation had not been removed. When the licensee removed the insulation to allow the residual oil to boil off, the oil i
,
soaked insulation' caught fire. The small fire was extinguished within 10 minutes by the fire brigade and the turbine was tripped. No damage to plant equipment or adverse impact on plant personnel occurre l, h
following the event, the licensee removed approximately 50-feet of insulation, uhich was believed to be all of the oil soaked insulation, and wiped the pipes clean of all residual oil. However, another fire occurred on October 21 i during the subsequent turbine startup. The fire was extinguished within 10 'ninutes and, although not required, a notification of unusual event was conservatively declared. The operators commenced a power reduction to appreximately 25 percent power so that the extraction steam line temperature ,
would be reduced below the lube oil flash point and remained at that power *
level antil all the residual oil boiled of ;
The licensee expected that some residual oil and oil-soaked insulation may !
'
still be present and stationed a fire watch at the high pressure turbine. The fire watch remained while the residual oil boiled away and during the power ;
escalation. No additional fires occurre The licensee conducted interviews with personnel associated with the lube oil bearing flush to determine the root cause for the cracked coupling. The interviews were inconclusive. To minimize future cracking of the temporary '
bypass jumper piping, the licensee was considering using material stronger than PVC for bearing oil flushe .3 Conclusions The procedure for the test equipment used during an integrated ESAS test was !
inadequate, contributed to the deenergization of the Unit I safety-related bus, and was considered to be a violation. The failure to implement a condition report acticn item regarding an EDG speed sensing switch replacement was considered to be a violation. Insufficient removal of oil soaked insulation from the high pressure turbine steam extraction lines following a :
turbine lube oil spill resulted in two small fires during the Unit I startup ,
following the Refueling Datag OPERATIONAL SAFETY VERIFICATION (71707) Unit 1 - Reactor Building Sump and Building Close Out On October 10 the inspector toured the reactor building and performed a visual l inspection of the reactor building sump for debris prior to closecut of the :
reactor building following the Refueling Outage. No debris was identified in ;
the sum f
.
'
. . :
.
_9_
The tour of the reactor building by the inspector indicated most loose items were tied down and that the reactor building was well organized. The ,
inspector did identify, however, a radwaste bag containing protective clothing ;'
by the incore storage pit and loose scaffolding by the escape hatch. The licensee did not know why the bag was in the area, but subsequent calls made by the licensee confirmed that a contamination zone was being established by instrumentation and controls technicians to perform emergent work. The ;
scaffolding was present to complete electrical work and the licensee stated '
that both the bag and the scaffolding would be removed upon completion of the task and prior to final reactor building closeou .2 Unit 1 - Emergency Feedwater Pipe Vibration Event On October 12 pipe vibrations were noted by the licensee on the emergency feedwater system when Valve CV-2646 began to oscillate during full flow l testing per Procedure 1106.006, " Emergency Feedwater Pump Operation,"
i Revision 48, Supplement 10. Valve CV-2646 controlled flow from Emergency Feedwater Pump P-78 to Steam Generator E-24A. The valve controller gain setpoint was discovered to be 1.5V above the factory setpoint which caused the !
controller to be too sensitive. The rapid valve motion combined with feeding a cold steam generator caused insufficient back pressure to decelerate columns of water at high velocities resulting in excessive pipe vibrations. The licensee and the vendor readjusted the controller and inspected and adjusted ->
gain settings for controllers on Valves CV-2647, CV-2648, and CV-264 Excessive pipe vibration was not observed during subsequent emergency feedwater testin ,
The inspector independently confirmed the licensee's assessment of the ,
integrity of the emergency feedwater piping system by inspecting the system l from the Emergency Feedwater Pump P-7B discharge to the "D" ring in the reactor building. No signs of damage or leakage were detected. Piping supports and restraints were in good condition. The licensee's evaluation and i assessment of the pipe vibration was prompt and thorough,
,
3.3 Unit 1 - Oil Leakage to the Discharge Canal
>
On October 12 the licensee reported to the state of. Arkansas and the NRC that less than 3 gallons of oil from Hydrogen Seal Oil Cooler E-32 leaked into the discharge canal. A plug from an auxiliary cooling water tube became dislodged i following system maintenance resulting in a tube leak in the seal oil coole Auxiliary cooling water discharges to the canal. An oil containment boom, '
placed across the discharge canal prior to the performance of the system .
maintenance, prevented the oil from spreading beyond the discharge canal. The .;
impact to the environment was insignificant. The seal oil cooler was isolated i and the tube was subsequently replugge The inspector noted that oil discharges to the canal had occurred in >
'
three consecutive outages. The inspector reviewed the associated condition reports and concluded that the cause of the recent oil discharge was unique, ,
therefore, this was viewed as an isolated event. The licensee's actions were l
(
,
e
. -
.
. .
.
,
-10-appropriate and the decisicr to place the boom across the discharge canal prior to the system maintenance was conservativ .4 Unit 2 - Particles in High Pressure Injection Pump 2P-89A Lube Oil On October 28 the inspector reviewed the station logs ad noted that High Pressure Injection Pump 2P-89A was being frequently % < ated. The licensee stated that a relatively high number of particles were identified by an operator in the inboard bearing oil sight glass and as a result the pump oil was sampled and flushed. The sample results indicated that the bearing oil particle content was 1.5 to 2 times the acceptable administrative limits. The licensee determined that the particles were not metal wear particles or particles indicative of oil breakdown and sent the sample to an offsite laboratory for further analysis. The pump remain 3d operabl .5 Unit 1 - Degradation of RCP P-32C Middle Stage Seal On November 2 the licensee discovered that the second stage of the pump seal for RCP P-32C did not properb @vdop a pressure drop because the rotating face o-ring was displaced from the seat. The cause of the displaced o-ring was believed to be the failure to implement a vendor recommended modificatio The modification would have allowed the 0-ring to reser' following reverse pressurization during seal testin Further inspection will be performed to determine whether design change controls were properly implemented. This item is unresolved (313/9309-03).
3.6 Unit 1 - Reactor Building Tour Followina Forced Outage 1Fil On November 2 the inspectors toured the reactor building following the forced outage for the RCP seal replacement. The tour was performed between the licensee's preheatup and precritical tours. The inspectors identified several loose items in the reactor building. The articles included tools, small health physic items such as protective gloves, and other small debris. The licensee stated that, based on transport analysis, the likelihood for the items to be transported to the reactor building sump resulting in sump blockage during a design basis accident was remote. Additionally, the licensee stated that Procedure 1102.001, Revision 52, " Plant Preheatup and Precritical Checklist," Attachment F, " Reactor Building Inspection," was too restrictive in requiring that all items be removed from the reactor buildin The licensee stated that the reactor building inspection procedure was intended to be performed as an iterative process where semi-permanent equipment, such as welding machines and scaffolding, were to be listed in the checklist for inventory purposes and evaluation. Smaller items were to be removed simultaneously with the building tour. The smaller items were not required to 'ae listed in the attachment. The failure to remove all loose items during the licensee's preheatup reactor building inspection as required by Procedure 1102.001 was a violation of Technical Specification 6. However, the safety significance was minor. This violation is not being cited
~
.
l
>
.
-11-because the criteria in Paragraph VII.B.1 of Appendix C to 10 CFR Part 2 of the NRC's " Rules of Practice" were satisfie Prior to heatup, the NRC identified that materials were consolidated and immediately removed from the reactor building. An additional walkdown was <
performed by the licensee prior to the precritical walkdown inspection to identify any other possible debris. The licensee committed to revise Procedure 1102.001 to clarify the action and scope of the reactor building housekeeping walkdowns to ensure effective controls for the preheatup and precritical building walkdowns are maintained. This action is expected to be completed by January 15, 199 .7 Unit 1 - Fire Water Leak in the Reactor Building On November 2 the inspector identified water dripping from the reactor building Fire System Deluge Valve UAV-5614 into the ICCMDS Junction Box JB-940B. The licensee stated that the fire water dripped into the junction box from the valve following fire system surveillance while the unit was shutdown. The valve's tell tale drain was routed near the junction box in accordance with the original desig The junction box was a cable pull box containing splices which provided a connection between the narrow range hotleg transmitters and the ICCMDS cabinets located outside the reactor buildin .
The licensee stated that the reactor building fire system was isolated at power so continued leakage would not occur. The copper tubing tell tale drain was bent to reduce the possibility of water dripping into the junction box, and the box internals were dried. A plant engineering action request was also initiated to permanently reroute the drain line. The inspector asked if the water intrusion into the junction box contributed to the deficiencies listed in three recent condition reports related to ICCMDS. The licensee stated the condition report deficiencies were associated with circuit. system repairs located outside the reactor buildin The inspector concluded that the original location of the drain line was inadequate and that the licensee's actions were appropriat .8 Unit 2 - Misalignment of PASS Valves On November 3 the inspector identified to the licensee that Chloride Analyzer Isolation Valve 2SV-5998 was misaligned closed and Chemical Analyzer Drain Valve 2SV-5945 was misaligned opened on the PAS Procedure 1617.009, Revision 11, " Panel 2C357 Valve Alignment," required Valve 2SV-5998 to be open and Valve 2SV-5945 to be closed. The licensee investigated the mispositioned valves and repositioned the valves in accordance with Procedure 1617.00 Valve 2SV-5998 functioned as an isolation valve for a PASS chloride analyze t Valve 2SV-5945 was used to isolate the boron analyzer and chlorine chemical
,.
-
c
,
.
'
-12-analyzer common header drain from the auxiliary building sum These three analyzers were no longer required and were previously remove t The valves were found misaligned following a chemistry training session on PASS operation that used Procedure 1617.009. The licensee was aware that Valve 2SV-5998 was closed and that this was the desired position for this valve due to the removal of the PASS chloride analyzer. The licensee was controlling the position of this valve by utilizing Piping and Instrumentation !
Diagram M-2237, Sheet 4, " Flow and Control Diagram Postaccident Sampling System," which indicated the valve as closed. In order to meet the intent of ;
the diagram, licensee personnel left Valve 2SV-5998 in the closed positio Although it was recognized that Procedure 1617.009 should have been the controlling document for the valve's positioning, a procedure revision was not :
+
initiate The licensee stated that the responsible individual in this event was counseled concerning the appropriate actions which should have been take ;
Chemistry personnel responsible for procedure changes were instructed on the proper protocol for procedure changes following identification of procedural deficiencies. Procedure 1617.009 was subsequently revised to correct the ,
position of Valve 2SV-599 In addition, Procedure 1617.009 required that Valve 2SV-5945 be closed when the PASS was in the standby mode. The licensee conducted an investigation and could not determine why this valve was mispositioned. The failure to position Valves 2SV-5945 and 2SV-5998 in accordance with the requirements of Procedure 1617.009 was considered to be a violation of Technical Specification 6.8.1 (368/9309-02).
3.9 Unit 2 - Main Feedwater Pump Turbine Speed Transient On November 3 the speed of both main feedwater pumps increased resulting in elevated s'.eam generator levels. The control systems were left in automatic, ,
and plant parameters returned to normal without operator intervention. The '
transient lasted about 10 minutes and resulted in a loss of. plant output of i approximately 10 megawatt ,
The licensee was not able to identify the cause of the transient. Test recorders were connected .in an attempt to identify the cause of the transient, however, the event did not recur. Condition Report 2-93-0264 was initiated :
and categorized as nonsignifican .10 Unit 1 - Repair of Main feedwater P. ump P-1A On November 11 the lube oil pressure decreased on Main Feedwater Pump P-1 Reactor. power was decreased to 43 percent for repairs. The licensee repaired a broken flange gasket on the discharge piping from Lube Oil Pump P-27A and adjusted the check valve which is used to determine the correct bearing lube oil pressure settin I
,
!
~
'
i
~
Main Feedwater Pump P-1A was returned to service and power was escalated to 100 percent. Condition Report 1-93-0529 was written and classified as !
significan .11 Unit 1 - Positioning of RCP P-32C Interaasket Leakoff Valves ':
On November 10 the licensee noted that RCP P-32C intergasket leak annunciator momentarily alarmed. The inspector questioned if the annunciator was cleared by closing RCP Intergasket Leak Isolation Valves RBS-11C and RBS-12C. The .
licensee stated that the valves remained open as required by the procedure and speculated that the alarm was caused by a spurious signal or that conditions .
near the temperature probe changed to clear the alar l The inspector discovered that a plant evaluation action request had previously been written to initiate a procedure improvement form to close the intergasket isolation valves for RCP P-32B and P-32C prior to plant startup following completion of Refueling Outage IR11. The basis for the system engineering recommendation was to limit the potential for steam cutting the gaskets' >
sealing surface if the gaskets began leakin The inspector determined that the procedure improvement form was not fully implemented due to an oversight by the licensee. However, the inspector determined that operation with the intergasket isolation valves in the open position was within the RCP's design basis and, therefore, a nuclear safety ,
concern did not exist. The licensee stated the procedure improvement form was
'
a proactive vehicle for procedure enhancement and the oversight was of minor safety significanc .12 Units 1 and 2 - Site Selection for Spent Fuel Storage Casks .
The licensee planned to store spent fuel in a ventilated storage cask which would be installed under the 500 KV transmission lines. The inspector asked to review documentation which indicated that-the casks were designed to withstand fault currents from a failed transmission lin ,
i The ventilated storage cask vendor provided the licensee with a memorandum ,
which stated that there are no concerns with the placement of the casks under the transmission lines. The basis for this conclusion was that grounding .
would be provided to eliminate concerns due to induced electrical field Fault currents were not clearly addressed. The licensee planned to obtain ,
additional confirmation that the cask design would withstand fault currents- !
from a failed transmission line. Further inspection in this area is planned ,
and will be tracked as IFI 313/9309-04; 368/9309-0 .13 Conclusions ;
i Following completion of Refueling Outage IRll, the inspection of the reactor building sump revealed that the sump was free of debris. Items identified by the inspector during the reactor building tour were a result of emergent. wor ,
_
~
. .
.
.
-14-
,
The licensee performed a prompt and thorough assessment of the emergency feedwater pipe vibration event. The hydrogen seal oil cooler oil leak to the
'
discharge canal was an isolated event with minimal environmental consequence ;
The licensee's decision to place the oil containment boom across the canal prior to system maintenance was conservative. The licensee's failure to implement a vendor recommended modification may have contributed to RCP P-32C seal degradation and will be tracked as an unresolved item. The discovery of loose additional items following the licensee's preheatup reactor building inspection after Forced Outage IF11 was a noncited violation. Inadequate design considerations for routing a deluge valve drain line in the vicinity of '
an ICCMDS junction box and the licensee's failure to identify fire water leakage into the box was a weakness. The failure to fully implement plant engineering action request (PEAR) recommendations to close intergasket leak
!
isolation valves on two RCPs was a licensee oversigh A strength was noted when the licensee proactively identified particles in the
Unit 2 High Pressure Injection Pump 2P-89A lube oil system. A violation was !
identified as a result of two misaligned valves on the PASS for Unit ,
'
4 MONTHLY MAINTENANCE OBSERVATION (62703) B 4.1 Unit 2 - Replacement of Control Room Recirculation Damper Isolation Valve (JO 00903456) ;
On November 5 the inspector observed the electricians deenergize control room Recirculation Fan 2VSF-9 Damper Isolation Valve 2SV-8607-1 and replace the valve because the valve chattered during performance of a previous surveillance. The valve was replaced under a Priority 2 job order, which was appropriate for this piece of equipment. The work was performed well by .
knowledgeable elactricians using calibrated equipment. Lifted leads were appropriately documented and the licensee quality control inspector performed -
verification of system restoratio f The licensee stated that the valve, which was an American Switch Company Model NP-8320B175, chattered because the shading ring and the solenoid '
deformed as a result of several valve stroking operations. Further inspection is planned of the licensee's program to ensure solenoid-valve reliability in this application. This item will be tracked as IFI 368/9309-0 .2 Unit 1 - RCP Under Power Relay Test (JO 00899955) .;
On November 8 the inspector observed the performance of a MPM task. The test was coordinated with the completion of corrective maintenance J0 00882210' As
.
a result postmaintenance testing and MPM testing were accomplished at the same time. All activities were accomplished in accordance with procedure .
)
1
l
,
~
. .
l
~
-15-
.;
4.3 Units 1 and 2 - Schedulina The inspector attended daily maintenance scheduling meetings and observed that operations priorities were communicated to maintenance personnel. Observed maintenance activities were appropriately prioritize ,
i 4.4 Conclusions All observed maintenance activities were appropriately prioritized and ,
performed well. An inspection followup item was opened to evaluate the reliability of the Unit 2 control room recirculation fan isolation dampe solenoid valv ,
,
5 BIMONTHLY SURVEILLANCE OBSERVATION (61726)
5.1 Unit 1 - Local Leak Rate Testing of the Personnel Hatch (JO 00903327) '
.
-
On November 4 the inspector observed the local leak rate testing of the '
personnel hatch for final reactor building closure. The technicians performing the test were knowledgeable and adhered to the requirements of Procedure 1304.020, Revision 9, " Unit 1 Reactor Building Access and Ventilation Leak Rate Testing," Supplement 2. Leak rate data was collected utilizing the pressure decay method and calibrated instruments. The inspector ,
'
verified that there was no leakage on either the inner or outer seals of the personnel hatc .2 Unit 1 - ESAS Digital Subsystem 1 Test (JO 00902893) ,
On November 4 the inspector observed performance of Procedure 1304.045,- ,
Revision 12, " Unit 1 ESAS Digital Subsystem No.1 Monthly Test." The performance of the test was excellent. The technicians were knowledgeable and ,
adhered to the procedure while conducting the surveillanc .3 Unit 1 - Nuclear Instrumentation Calibration at Power (JO 00903040) :
On November 4 the inspector observed the calibration of the. nuclear !
instrumentation channels following Forced Outage IF11. The instrumentation and controls technician identified one value as being high but within the .
,
acceptance criteria. Operations personnel requ'ested that an adjustment to the channels be performed even though the initial values were within the . :
'
acceptance criteria. All channels were appropriately adjusted-in accordance with the procedur .,
!
5.4 Unit 2 - Channel D Reactor Protection System Surveillance Testinq l
-
(JO 00902910) .
On November 10 the inspector observed portions of the performance of I Procedure 2304, " Plant Protection System Channel D Test." The technicians -
carefully followed the test procedure. One technician, stationed in the front of the control room, used a telephone headset to remain in constant f
y - -
r-
'
. .
.
-16- :
.
communication with the technicians that were manipulating the reactor ;
protection system controls in the rear of the control room. The expected alarms were clearly marked for the benefit of the operators. No problems were identifie ,
5.5 Unit 1 - Quarterly Inspection of Diesel Fire Pump Enaine K-5 (JO 0092982)
On November 10 the inspector observed portions of the performance of :'
Procedure 1307.004, " Diesel Fire Pump Engine (K-5) Quarterly Surveillance."
The inspection was scheduled quarterly in accordance with vendor recommendations. The Safety Analysis Report for both units required that an ;
inspection be performed in accordance with the manufacturer's recommendations on an 18-month interva :
lhe coordination between the electricians and operations personnel was -
acceptable. Steps 7.1 through 8.1.3 contained instructions for obtaining a hold order. The craftsman obtained a hold order from operations personnel prior to initiating the performance of the Procedure 1307.004. The procedure steps for obtaining a hold order had been performed correctly, but they were not documented as the steps were performed. The inspector was concerned that this practice sent a confusing message to the craftsman regarding procedure adherence. The licensee planned to review their expectations in this are .6 Conclusions i
,
Observed surveillance test activities were performed well and in accordance t with the procedures. However, the Unit 1 diesel fire pump inspection was not documented as stcps were performe ONSITE REVIEW 0F LERS (92700) [ (Closed) LER 368/92-009: " Leak Test Surveillance of Excore Nuclear Instrumentation Detectors not Performed as Required by Technical Specifications due to Procedural Inadecuacies"
This LER involved the failure to test excore nuclear instrumentation fission detectors for leakage within 31 days prior to being subjected to core flux as !'
required by Technical Specification 4.7.9.1.2.c. The root cause was determined to be inadequate procedures for implementing the triggering -!
mechanism necessary to ensure that the surveillance requirement was identified'
prior to installing the detector Fission detectors located in the warehouse were. tagged to identify leak ;
testing requirements. Procedure 1022.012, " Storage, Control and -j Accountability of Special Nuclear Material," was revised to include the test !'
requirement Procedure 1622.020, " Leak Test of Sealed Sources," was revised to require tagging of startup sources and fission detectors. Additionally as part of the licensee's corrective actions, the component data base used by ,
planning personnel to prepare J0s for work involving fission detectors was revised to add a note referencing the Technical Specification requirement i
.
-
"
. .
.
-17-Based on the inspectors review of Condition Report 2-92-0441, the licensee's f component data base, Procedure 1022.012 and Procedure 1622.020, all corrective actions have been complet l 6.2 (Closed) LER 313/93-003: " Low Pressure Injection Pump Potentially Incapable of Performina its Recirculation Mode function Due to Improper .
Pump / Motor Coupling which Resulted from Inadeouate Procedural Guidance"
-
The inspector was briefed by the licensee regarding the investigation techniques which led to the determination that Low Pressure' Injection Pump P-34 may have been incapable of performing its recirculation mode function following a loss _of coolant accident. The licensee's investigation was documented in Condition Report 1-93-291 and the referenced LE The root cause of high temperature alarms was subtle and not easily determined. The licensee determined that the plant procedure governing maintenance of the pump did not provide adequate guidance for determining th magnetic center of the motor. As a result, a coupling was reinstalled approximately .316 inch too close to the motor. Subsequent regreasing of the coupling limited 'he thermal expansion room for the shaft. When heated water
was pumped, thermal expansion of the shaft was enough to effect the thrust loading on the outboard motor bearing and lubrication was restricted. The ;
licensee investigation was thorough and effectiv Revision of other horizontal pump procedures to clarify the correct method for determining motor magnetic centers was planned and was tracked in the licensee's commitment management system and the licensee's corrective action system. All other corrective actions were complet FOLLOWUP (92701) (Closed) IFI 313/9305-01: Further Review of Work Prioritization of JO 00735100 and the Effect of Accumulation of Sodium Hydroxide on Valve CA-49 This item involved a further review by the inspector of work prioritization of .
J0 00735100. This JO was written to stop leakage from Valve CA-49. The effect of accumulation of sodium hydroxide on Valve CA-49 was also reviewe During this inspection period, a freeze seal was formed on the Sodium Hydroxide Tank- T-10 discharge line upstream from Valve CA-49. JO 00735100 was ,
completed and the valve body to bonnet leak was repaired. The . visible rust formation-located on the body of Valve CA-49 noted by the ir.spector was due to i the carbon steel bonnet bolts corroding from contact with the sodium hydroxide. Based on the observation'of a portion of the maintenance '
activities for Valve CA-49 and review of Procedure 1409.509, " Freeze Sealing for CA-49 Repair," the inspectors evaluation is complet ,
,=
-
. . ;
'
' ATTACilMENT 1 ;
i
,
1 PERSONS CONTACTED t Licensee Personnel ;
i C. Anderson, Unit 2 Operations Manager ;
>
S. bennett, Licensing Acting Supervisor S. Boncheff, Licensing Specialist i
'
S. Cotton, Radiation Protection and Radwaste Manager B. Day, Unit 1 System Engineering Manager l R. Douet, Unit 1 Maintenanta Manager l i
R. Espolt, Technical Assistance to Unit 2 Plant Manager
!
B. McKelvy, Chemistry-Superiniandent T. Mitchell, Unit 2 System Engineering l W. McKelvy, Chemistry Supervisor L. Rushing, Unit 1 System Engineering Supervisor l e
J. Taylor-Brown, Quality Coordinator J. Vandergrift, Unit 1 Plant Manager J. Yelverton, Vice President Operations
.
The personnel listed above attended the exit meeting. In addition to the personnel listed above, the inspectors contacted other personnel during this
+
inspection perio j l
2 EXIT MEETING An exit meeting was conducted on November 18, 199 During this meeting, the inspectors reviewed the scope and findings of the report. The licensee l
'
acknowledged the inspection findings and provided additional information regarding mitigating actions taken prior to the turbine fire and the ;
importance of the RCP intergasket leakoff valve alignment recommendation i The licensee did not identify as proprietary any information provided to, or reviewed by, the inspector >
!
!
I
!
!
l i
i
!
,
I
!
t
$
l
..
I